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PHX MINERALS INC. (PHX)·Q2 2024 Earnings Summary

Executive Summary

  • Q2 2024 delivered record royalty production and highest total quarterly production since Q2 2018, with net income of $1.3M ($0.04 diluted EPS) and adjusted EBITDA of $6.4M, driven by high-interest Haynesville wells and disciplined cost control .
  • Management raised the fixed quarterly dividend 33% to $0.04 and reduced debt to $28.75M (TTM debt/adjusted EBITDA 1.32x), highlighting balance-sheet strength and cash generation .
  • Guidance was updated: 2024 total production 9,700–10,300 Mmcfe; cash G&A $9.5–$9.9M; TG&M per Mcfe $0.40–$0.50; LOE $1.1–$1.3M, reflecting cost-bearing Haynesville volumes and steady operator activity across PHX acreage .
  • Near-term narrative: sequential production surge appears “anomalous” from timing of high-impact wells; management flagged expected lumpiness and embedded conservatism in H2 modeling; medium-term: LNG and AI/data-center demand could catalyze volumes and price normalization .

What Went Well and What Went Wrong

  • What Went Well

    • Record royalty volumes (+46% q/q to 2,709 Mmcfe); total volumes +40% q/q to 2,968 Mmcfe, highest since Q2 2018; “quality of our asset base” driving growth despite a challenging macro .
    • Balance sheet improvement: debt reduced to $28.75M; debt/TTM adjusted EBITDA down to 1.32x; dividend raised 33% to $0.04 per share .
    • Management tone confident on medium-term catalysts: “pending demand for new LNG export facilities” and “AI-generated power demand” support optimism; hedge program protected downside (Q2 realized hedge gains $1.18M) .

  • What Went Wrong

    • Higher TG&M costs with cost-bearing Haynesville leases; TG&M increased to ~$1.54M (+83% q/q), pressuring per-unit economics despite volume gains .
    • Derivative headwind: Q2 recorded net loss on derivatives of ($0.4M), with non-cash loss of ($1.6M) partially offset by settled gains .
    • Continued operational lumpiness and >25% annual corporate decline rate require ongoing well conversions to sustain growth; management embeds conservatism in H2 guide .

Financial Results

MetricQ2 2023Q1 2024Q2 2024
Total Revenue ($)$17,410,653 $7,869,418 $9,541,235
Net Income ($)$1,112,156 ($183,615) $1,295,771
Diluted EPS ($)$0.03 ($0.01) $0.04
Adjusted EBITDA ($)$11,033,201 $4,607,034 $6,426,167
Net Income Margin (%)6.4% (=$1,112,156/$17,410,653) (2.3%) (=$-183,615/$7,869,418) 13.6% (=$1,295,771/$9,541,235)
Adj. EBITDA Margin (%)63.3% (=$11,033,201/$17,410,653) 58.6% (=$4,607,034/$7,869,418) 67.3% (=$6,426,167/$9,541,235)

Segment revenue breakdown

Revenue ComponentQ2 2023Q1 2024Q2 2024
Royalty Interest Sales ($)$14,995,239 $6,176,274 $8,818,964
Working Interest Sales ($)$1,920,975 $913,934 $1,007,042
Nat Gas, Oil & NGL Sales ($)$16,916,214 $7,090,208 $9,826,006
Gains (Losses) on Derivatives ($)$208,495 $627,492 ($418,997)
Lease Bonuses & Rental ($)$285,944 $151,718 $134,226

KPIs and unit costs

KPI / CostQ2 2023Q1 2024Q2 2024
Total Production (Mcfe sold)5,084,557 2,116,776 2,967,779
Royalty Production (Mcfe)1,946,196 1,857,147 2,709,090
Working Interest Production (Mcfe)298,521 259,629 258,689
Gas Mcf Sold4,164,955 1,700,108 2,464,846
Oil Barrels Sold89,088 37,260 51,828
NGL Barrels Sold64,179 32,184 31,994
Avg Gas Price per Mcf (pre-hedge) ($)2.07 2.10 2.05
Avg Gas Price per Mcf (after hedge) ($)2.78 3.08 2.57
% of Gas Sales Hedged48% 62% 38%
Avg Oil Price per Bbl (pre-hedge) ($)76.81 76.01 77.38
Avg Oil Price per Bbl (after hedge) ($)75.72 76.19 75.38
% of Oil Sales Hedged30% 37% 25%
LOE per Working Interest Mcfe ($)1.21 1.28 1.14
TG&M per Mcfe ($)0.47 0.40 0.52
Production & Ad Valorem Tax per Mcfe ($)0.19 0.19 0.20
G&A per Mcfe ($)1.20 1.58 0.92
Cash G&A per Mcfe ($)0.92 1.25 0.69

Guidance Changes

MetricPeriodPrevious GuidanceCurrent GuidanceChange
Mineral & Royalty Production (Mmcfe)FY 2024Not numerically disclosed in prior-quarter press materials 8,700–9,100 Updated range provided
Working Interest Production (Mmcfe)FY 2024Not numerically disclosed 1,000–1,200 Updated range provided
Total Production (Mmcfe)FY 2024Not numerically disclosed 9,700–10,300 Updated range provided
% Natural GasFY 2024Not numerically disclosed 79%–82% Updated range provided
TG&M per Mcfe ($)FY 2024Not numerically disclosed $0.40–$0.50 Updated higher on cost-bearing wells
Production Tax (% of pre-hedge sales volumes)FY 2024Not numerically disclosed 5.25%–6.25% Updated range provided
LOE (absolute $000s)FY 2024Not numerically disclosed $1,100–$1,300 Updated range provided
Cash G&A (absolute $000s)FY 2024Not numerically disclosed $9,500–$9,900 Updated range provided
Dividend per shareQuarterly$0.03 (May declaration) $0.04 (announced subsequent to Q2 results) Raised 33%

Earnings Call Themes & Trends

TopicPrevious Mentions (Q4 2023, Q1 2024)Current Period (Q2 2024)Trend
LNG demand & price normalizationExpected LNG facility commissioning to improve sentiment/prices in mid–late 2024; Haynesville positioned to feed LNG “Pending demand for new LNG export facilities” bolsters medium-term optimism Strengthening
AI/data-center power demandAI/data center demand could materially increase natural gas demand AI-generated power demand “clearly on the horizon” supporting contango Strengthening
Haynesville development & lumpinessSome operators deferring completions; steady permits/rig activity on PHX minerals High-interest Haynesville wells drove record volumes; timing causes volatility; cost-bearing leases lift TG&M Mixed: higher volumes, higher TG&M
SCOOP SpringBoard IIIEarly results exceeded expectations; multi-bench development potential “Material increase in development activity” and several high-interest wells in process Positive momentum
Hedging & downside protectionConsistent program; ~48% gas protected at ~$3.34 (Q1) Q2 realized hedge gains $1.18M; ~42% FY gas protected at ~$3.34; ~35% oil protected at ~$65.48 Stable/Protective
Cost structure (TG&M/Taxes)TG&M decreased with mix; production taxes linked to LA volumes TG&M up 83% q/q with cost-bearing leases; production taxes up 52% q/q Cost pressure from mix

Management Commentary

  • Strategic transformation: “Today… royalty volumes and reserves represent approximately 90%… non-op working interest about 10%,” enabling higher-margin growth and dividend support .
  • Medium-term demand catalysts: “Pending demand for new LNG export facilities… and increased demand… to meet growing AI-generated power demand is clearly on the horizon” .
  • Balance sheet discipline: “Strong cash generation enabled us to reduce our debt… lowering our debt-to-adjusted EBITDA… to 1.32x” .
  • On lumpiness: “As a mineral holder, we do not control timing… we expect continued quarterly lumpiness in our volumes” .
  • SpringBoard III SCOOP: “We are especially excited about the material increase in development activity… Springboard III area of the SCOOP” .

Q&A Highlights

  • Outlier vs trend: Management views Q2’s surge as timing of high-interest wells rather than a one-off; similar wells are in development, but quarter-to-quarter timing is uncertain .
  • H2 trajectory: Embedded conservatism; despite expected declines post initial flush, 2025 volumes should improve if pace of conversions persists and operators maintain activity .
  • TG&M modeling: TG&M varies idiosyncratically with cost-bearing vs cost-free lease mix; ranges provided to reflect quarterly volatility .
  • Well quality mix: Haynesville wells arrive at much higher rates than Oklahoma, driving “high-impact” quarter; normalized mix would still have delivered strong sequential growth .
  • Shut-ins/recompletions: No material shut-in impacts noted recently; some positive offsets from completions of offsets, particularly in Haynesville .

Estimates Context

  • Wall Street consensus (S&P Global) for Q2 2024 EPS and revenue was unavailable for PHX due to mapping limitations; therefore, beat/miss vs estimates cannot be asserted for this quarter. Values retrieved from S&P Global were unavailable.*

Where estimates may need to adjust:

  • Sequential EBITDA margin expansion and record royalty volumes suggest upward revisions to near-term volume and EBITDA run-rate assumptions, balanced by higher TG&M under cost-bearing leases and embedded H2 conservatism .

Key Takeaways for Investors

  • Q2 was a volume inflection driven by high-interest Haynesville wells; expect lumpiness, but medium-term trajectory supported by robust wells-in-progress/permits and improving demand backdrop (LNG, AI) .
  • Cash discipline: reduced debt (1.32x TTM debt/adj. EBITDA) and dividend raised 33% signal balance-sheet strength and shareholder returns; liquidity supports selective mineral acquisitions .
  • Mix matters: higher cost-bearing Haynesville activity lifts TG&M; model a wider TG&M range ($0.40–$0.50/Mcfe) and incorporate production tax sensitivity to Louisiana volume .
  • Hedge coverage mitigates downside while retaining upside via collars; maintain cautious price assumptions with non-cash derivative volatility .
  • SpringBoard III SCOOP remains a multi-year catalyst (oil/NGL-rich, multi-bench potential) for diversified mix and cash flow .
  • Without reliable Street consensus, focus on sequential/YoY fundamentals: EBITDA margin expansion to 67.3% and net income margin to 13.6% in Q2, both aided by volumes and lower G&A per Mcfe .
  • Near-term trading: watch for rig/permit cadence and timing of additional high-interest wells; H2 results may normalize from Q2 flush, but continued conversions can sustain annual royalty growth .